Enhancing foam rheological properties using water-soluble thickener

ABSTRACT

An aqueous wellbore fluid may include a surface active agent package in an amount ranging from 1 to 20 gpt, a thickener in an amount ranging from 0.01 to 0.3 wt. %, and an aqueous base fluid. The surface active agent package may include an α-olefin sulfonate, a terpenoid, and isopropyl alcohol. The thickener may include a biopolymer.

Enhanced oil recovery (EOR) enables the extraction of hydrocarbonreserves that conventional primary and secondary recovery processes,such as gas or water displacement, cannot access. Gas injection is oneof the most widely used EOR techniques as application of an oil-miscibleinjection gas can greatly improve oil recovery in gas-swept zones.Despite the reported achievements of gas injection for EOR, one majorchallenge that still needs to be overcome to make this technique moreefficient is the associated poor volumetric sweep efficiency. The keyfactors that contribute to this challenge are the low density andviscosity of injected gas relative to reservoir fluids, as well asreservoir features such as permeability variance.

For instance, gas injection generally provides decreased oil recoverywhen applied in variably-permeable wells. In such circumstances, the gaswill preferentially sweep the high permeability intervals, leaving theless permeable intervals unswept and consequently not recovering aportion of the reserve. Additionally, the mobility difference betweeninjected gas and other fluids in a formation may result in earlybreakthrough of gas, resulting in much of the residual oil beingbypassed. This provides an increased gas to oil ratio, making theoverall process less efficient.

The use of foams is one of the most promising techniques to overcome thedifficulties posed by variable permeability reservoirs and improve thevolumetric sweep efficiency. Foam can plug the high permeabilityintervals by increasing the apparent viscosity, and reducing therelative permeability, of the injected gas. Generally, foams aregenerated by mixing the injection gas with a surfactant-containinginjection water. The injection of alternate slugs of gas and surfactant(which may also be referred to as a surface active agent) generates foamin the reservoir due to a reduction of interfacial tension at thegas-liquid interface. However, providing a foam having a sufficientlong-term stability is difficult. Factors such as harsh reservoirconditions, high temperatures, salinity, rock-fluid and fluid-fluidinteractions, decrease foam stability.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments disclosed herein relate to aqueous wellborefluids that include a surface active agent package, a thickener, and anaqueous base fluid. The surface active agent package may comprise anα-olefin sulfonate, a terpenoid, and isopropyl alcohol, and be containedin the wellbore fluid in an amount ranging from 1 to 20 gpt. Thethickener may comprise a biopolymer and be contained in the wellborefluid in an amount ranging from 0.01 to 0.3 wt. %.

In another aspect, embodiments disclosed herein relate to methods forrecovering hydrocarbons from a hydrocarbon-containing formation Themethods may include injecting into the hydrocarbon-containing formationa wellbore fluid, injecting into the hydrocarbon-containing formation agas that mixes with the wellbore fluid, generating a foam in theformation, introducing a fluid into the hydrocarbon-containingformation, thereby displacing hydrocarbons from thehydrocarbon-containing formation, and recovering the hydrocarbons. Thewellbore fluid may comprise a surface active agent package, a thickener,and an aqueous base fluid. The surface active agent package may comprisean α-olefin sulfonate, a terpenoid, and isopropyl alcohol, and becontained in the wellbore fluid in an amount ranging from 1 to 20 gpt.The thickener may comprise a biopolymer and be contained in the wellborefluid in an amount ranging from 0.01 to 0.3 wt. %.

In another aspect, embodiments disclosed herein relate to methods ofpreparing an aqueous wellbore fluid that include mixing a surface activeagent package, a thickener, and an aqueous base fluid. The surfaceactive agent package may comprise an α-olefin sulfonate, a terpenoid,and isopropyl alcohol, and be contained in the wellbore fluid in anamount ranging from 1 to 20 gpt. The thickener may comprise a biopolymerand be contained in the wellbore fluid an amount ranging from 0.01 to0.3 wt. %.

In a further aspect, embodiments disclosed herein relate to methods forenhancing the recovery of hydrocarbons from a hydrocarbon-containingformation. The methods may include injecting into thehydrocarbon-containing formation a wellbore fluid and injecting into thehydrocarbon-containing formation a gas that mixes with the wellborefluid, generating a foam in the formation. The wellbore fluid maycomprise a surface active agent package, a thickener, and an aqueousbase fluid. The surface active agent package may comprise an α-olefinsulfonate, a terpenoid, and isopropyl alcohol, and be contained in thewellbore fluid in an amount ranging from 1 to 20 gpt. The thickener maycomprise a biopolymer and be contained in the wellbore fluid in anamount ranging from 0.01 to 0.3 wt. %.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a flowchart depicting an enhanced oil recovery (EOR) processin accordance with one or more embodiments of the present disclosure.

FIG. 2 is a schematic representation of a foam rheometer apparatus.

FIG. 3 is a graph showing foam viscosity versus shear rate for twowellbore fluids of one or more embodiments of the present disclosure.

FIG. 4 is a graph showing foam viscosity versus shear rate for twowellbore fluids of one or more embodiments of the present disclosure.

FIG. 5 is a graph showing foam viscosity versus shear rate for twowellbore fluids of one or more embodiments of the present disclosure.

FIG. 6 is a graph showing foam viscosity versus shear rate for twowellbore fluids of one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments in accordance with the present disclosure generally relateto wellbore fluids that contain a surface-active agent package and athickener, and methods of using the fluids in processes such as EOR andfracturing. Methods of one or more embodiments may involve generatingfoams in a hydrocarbon-containing subterranean formation. Such methodsmay modify the injection profile of the formation during EOR.

The formulations may be used in low-viscosity aqueous solutions thatgenerate foams having an increased viscosity. The resulting foamsdemonstrate increased stability under high temperature and pressureconditions, making them highly suitable for use in downholeenvironments.

The wellbore fluids of one or more embodiments of the present disclosuremay include, for example, water-based wellbore fluids. The wellborefluids may be fracturing fluids or EOR fluids, among others.

Water-based wellbore fluids of one or more embodiments may have anaqueous base fluid. The aqueous fluid may include at least one of freshwater, seawater, brine, water-soluble organic compounds, and mixturesthereof. The aqueous fluid may contain fresh water formulated to containvarious salts in addition to the first or second salt, to the extentthat such salts do not impede the desired nitrogen-generating reaction.The salts may include, but are not limited to, alkali metal halides andhydroxides. In one or more embodiments, brine may be any of seawater,aqueous solutions wherein the salt concentration is less than that ofseawater, or aqueous solutions wherein the salt concentration is greaterthan that of seawater. Salts that are found in seawater may includesodium, calcium, aluminum, magnesium, potassium, strontium, and lithiumsalts of halides, carbonates, chlorates, bromates, nitrates, oxides,phosphates, among others. Any of the aforementioned salts may beincluded in brine. In one or more embodiments, the density of theaqueous fluid may be controlled by increasing the salt concentration inthe brine, though the maximum concentration is determined by thesolubility of the salt. In particular embodiments, brine may include analkali metal halide or carboxylate salt and/or alkaline earth metalcarboxylate salts.

The wellbore fluids of one or more embodiments may include a surfaceactive agent package, which contains a surface active agent (orsurfactant). In some embodiments, the surface active agent package mayinclude one or more of a terpenoid, an anionic surfactant, and a polarcarrier. In some embodiments, the surface active agent may comprise allthree of a terpenoid, an anionic surfactant, and a polar carrier. Inparticular embodiments, the surface active agent may consist essentiallyof, and in some embodiments consist of, a terpenoid, an anionicsurfactant, and a polar carrier.

The wellbore fluids of one or more embodiments may comprise the surfaceactive agent in an amount of the range of about 0.5 to 25 gallons perthousand gallons (gpt). For example, the wellbore fluid may contain thesurface active agent in an amount ranging from a lower limit of any of0.5, 1, 2, 3, 5, 7, 10, and 12 gpt to an upper limit of any of 2, 4, 5,8, 10, 15, 20, and 25 gpt, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The surface active agent of one or more embodiments may include one ormore terpenoids. In some embodiments, the one or more terpenoids may beselected from a monoterpene, a diterpene, a triterpene and asesquiterpene. In some embodiments, the terpenoid may be one or more ofd-limonene, α-pinene, B-pinene, myrcene, geraniol, carvone,chrysanthemic acid, farnesol, humulene, squalene, careen, camphene,C-terpinene, Y-terpinene, and Sabinene. In particular embodiments, theterpenoid may be citrus terpenes and comprise d-limonene. In someembodiments, the citrus terpenes may comprise d-limonene in an amount of90% by weight (wt. %) or more, 92 wt. % or more, 94 wt. % or more, 95wt. % or more, 97 wt. % or more, 99 wt. % or more, 99.5 wt. % or more,or approximately 100 wt. %.

In one or more embodiments, the surface active agent may comprise theterpenoid in an amount of the range of about 1 to 30% by weight (wt. %),relative to a total weight of the surface active agent package. Forexample, the surface active agent package may contain the terpenoid inan amount ranging from a lower limit of any of 1, 2, 5, 10, 15, and 20wt. % to an upper limit of any of 3, 5, 10, 15, 20, 25, and 30 wt. %,where any lower limit can be used in combination with anymathematically-compatible upper limit.

The surface active agent package of one or more embodiments may includeone or more anionic surfactants. As used herein, anionic surfactants arecategorized as anionic if they possess groups having a negative chargeor no charge unless the pH is elevated to neutrality or above (e.g.carboxylic acids). In one or more embodiments, one or more ofcarboxylate, sulfonate, sulfate and phosphate groups may be the polar(hydrophilic) solubilizing groups found in anionic surfactants. Theanionic surfactants of one or more embodiments may include a monovalentor divalent cation. Examples thereof may include alkali metals such assodium, lithium and potassium, which may impart improved watersolubility; ammonium and substituted ammonium ions, which may provideboth water and oil solubility; and alkaline earth metals such ascalcium, barium, and magnesium, which may promote oil solubility.

The anionic surfactants of one or more embodiments may be selected fromone or more of acylamino acids (and salts), such as acylgluamates, acylpeptides, sarcosinates, taurates, and the like, carboxylic acids (andsalts), such as alkanoic acids (and alkanoates), ester carboxylic acids,ether carboxylic acids, and the like, sulfonic acids (and salts), suchas isethionates, alkylaryl sulfonates, alkyl sulfonates,sulfosuccinates, and the like, and sulfuric acid esters (and salts),such as alkyl ether sulfates, alkyl sulfates, and the like.

Particular anionic surfactants of one or more embodiments may includeα-olefin sulfonates, such as long chain alkene sulfonates, long chainhydroxyalkane sulfonates or mixtures of alkanesulfonates andhydroxyalkane-sulfonates. Other examples of the anionic surfactants ofone or more embodiments may include alkyl sulfates, alkylpoly(ethyleneoxy)ether sulfates and aromatic poly(ethyleneoxy)sulfates,and the ammonium, substituted ammonium, and/or alkali metal salts of thealkyl mononuclear aromatics such as alkylbenzene sulfonates. Forinstance, salts of alkylbenzene sulfonates or of alkyl toluene, xylene,cumene and phenol sulfonates; alkyl naphthalene sulfonate, diamylnaphthalene sulfonate, and dinonyl naphthalene sulfonate and alkoxylatedderivatives.

In one or more embodiments, the surface active agent package maycomprise the anionic surfactant in an amount of the range of about 1 to40 wt. %, relative to a total weight of the surface active agentpackage. For example, the surface active agent package may contain theanionic surfactant in an amount ranging from a lower limit of any of 1,5, 10, 15, 20, 35, and 30 wt. % to an upper limit of any of 5, 10, 15,20, 25, 30, 35, and 40 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The surface active agent package of one or more embodiments may includeone or more polar carrier such as water, alcohols, other polar solvents,or mixtures thereof. In particular embodiments, the polar carrier may bea low molecular weight primary, secondary, or tertiary alcohol. In someembodiments, the alcohol may be one or more selected from the groupconsisting of methanol, ethanol, propanol, isopropanol, butanol,isobutanol, and tertbutanol.

In one or more embodiments, the surface active agent package maycomprise the polar carrier in an amount of the range of about 1 to 40wt. %, relative to a total weight of the surface active agent package.For example, the surface active agent package may contain the polarcarrier in an amount ranging from a lower limit of any of 1, 5, 10, 15,20, 35, and 30 wt. % to an upper limit of any of 5, 10, 15, 20, 25, 30,35, and 40 wt. %, where any lower limit can be used in combination withany mathematically-compatible upper limit.

In one or more embodiments the surface active package may furthercomprise an additional aqueous solvent, which may be selected from thegroup consisting of fresh water, seawater, brine, water-soluble organiccompounds, and mixtures thereof. In some embodiments, the surface activepackage may consist essentially of a terpenoid, an anionic surfactant,and a polar carrier. In some embodiments, the surface active package mayconsist of a terpenoid, an anionic surfactant, and a polar carrier. Insome embodiments, the surface active package may consist essentially ofa terpenoid, an anionic surfactant, a polar carrier, and an additionalaqueous solvent. In some embodiments, the surface active package mayconsist of a terpenoid, an anionic surfactant, a polar carrier, and anadditional aqueous solvent.

In one or more embodiments, the surface active agent package maycomprise the terpenoid and the anionic surfactant in a weight ratio of3:1 to 1:4, by weight, where the weight ratio is given as the weight ofthe terpenoid to the weight of the anionic surfactant. For example, thesurface active agent package may contain the terpenoid and the anionicsurfactant in a weight ratio of ranging from a lower limit of any of3:1, 2:1, 1:1, and 1:2 to an upper limit of any of 1:1, 1:2, 1:3, and1:4, where any lower limit can be used in combination with anymathematically-compatible upper limit.

In one or more embodiments, the surface active agent package maycomprise the terpenoid and the polar carrier in a weight ratio of 3:1 to1:4, by weight, where the weight ratio is given as the weight of theterpenoid to the weight of the polar carrier. For example, the surfaceactive agent package may contain the terpenoid and the polar carrier ina weight ratio of ranging from a lower limit of any of 3:1, 2:1, 1:1,and 1:2 to an upper limit of any of 1:1. 1:2, 1:3, and 1:4, where anylower limit can be used in combination with anymathematically-compatible upper limit.

In one or more embodiments, the surface active agent package maycomprise the anionic surfactant and the polar carrier in a weight ratioof 4:1 to 1:4, by weight, where the weight ratio is given as the weightof the anionic surfactant to the weight of the polar carrier. Forexample, the surface active agent package may contain the anionicsurfactant and the polar carrier in a weight ratio of ranging from alower limit of any of 4:1, 3:1, 2:1, 1:1, and 1:2 to an upper limit ofany of 2:1, 1:1, 1:2, 1:3, and 1:4, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The wellbore fluids of one or more embodiments may include one or morethickeners, in combination with the surface active agent package. In oneor more embodiments, the thickeners may comprise a hydrophilic part, forinstance, a water-soluble polymer chain. The water-soluble chain may beone or more selected from the group consisting of polyethylene glycol,cellulose derivatives, acrylate chains, polyether chains, and polyesterchains. The thickeners may further comprise one or more hydrophobicgroups. The hydrophilic and hydrophobic groups may be bonded by, forexample, urethane bonds, ester bonds, ether bonds, urea bonds, carbonatebonds or amide bonds.

In one or more embodiments, the thickener may be one or more of apolyacrylamide and a polysaccharide. In particular embodiments, thethickener may be one or more of hydroxyethylcellulose,carboxymethylhydroxyethylcellulose, xanthan gum, hydrolyzedpolyacrylamide, acrylamide-containing copolymers, polyacrylamide,polyacrylic acid, glucan, dextran polyethyleneoxide, and polyvinylalcohol.

The wellbore fluid of one or more embodiments may comprise the thickenerin an amount of the range of about 0.01 to 5.0 wt. %. For example, thewellbore fluid may contain the thickener in an amount ranging from alower limit of any of 0.01, 0.05, 0.1, 0.15, 0.2, 0.25, 0.3, 0.5, 1.0,1.5, and 2.5 wt. % to an upper limit of any of 0.1, 0.2, 0.3, 0.4, 0.5,1.0, 2.0, 3.0, 3.5, 4.0, and 5.0 wt. %, where any lower limit can beused in combination with any mathematically-compatible upper limit.

In one or more embodiments, the wellbore fluids have a density that isgreater than 1.00 g/cm³. For example, the wellbore fluids may have adensity that is of an amount ranging from a lower limit of any of 1.00,1.05, 1.10, 1.15, and 1.20 g/cm³ to an upper limit of any of 1.05, 1.10,1.15, 1.20, and 1.25 g/cm³, where any lower limit can be used incombination with any mathematically-compatible upper limit.

In one or more embodiments, the wellbore fluids may have a viscosity at25° C. that is of the range of about 12 to 40 cP. For example, thewellbore fluids may have a viscosity at 25° C. that is of an amountranging from a lower limit of any of 12, 14, 16, 18, 20, 22, 25, and 30cP to an upper limit of any of 20, 22, 24, 26, 28, 30, 35 and 40 cP,where any lower limit can be used in combination with anymathematically-compatible upper limit. In some embodiments, the wellborefluids may have a viscosity at 25° C. of 40 cP or less, 30 cP or less,25 cP or less, or 20 cP or less.

In one or more embodiments, the wellbore fluids may have a viscosity at50° C. that is of the range of about 4 to 20 cP. For example, thewellbore fluids may have a viscosity at 50° C. that is of an amountranging from a lower limit of any of 4, 6, 8, 10, 12, and 14 cP to anupper limit of any of 10, 12, 14, 16, 18, and 20 cP, where any lowerlimit can be used in combination with any mathematically-compatibleupper limit. In some embodiments, the wellbore fluids may have aviscosity at 50° C. of 20 cP or less, 16 cP or less, 14 cP or less, 12cP or less, or 10 cP or less.

Methods in accordance with the present disclosure may comprise theinjection of a wellbore fluid into a formation. In addition to theinjection of the wellbore fluid, methods in accordance with one or moreembodiments further comprise the injection of a gas. The gas will, insome embodiments, be co-injected with the wellbore fluids. In someembodiments, the gas may be injected after the wellbore fluid. The gasmay be one or more of carbon dioxide, nitrogen, and methane. The carbondioxide of one or more embodiments may be injected as supercriticalcarbon dioxide. When the gas contacts the surface active agent package,a foam may be generated. In some embodiments, the use of nitrogen gasmay provide a more stable foam than carbon dioxide. This is because, thedissolution of carbon dioxide in the wellbore fluid may result in a pHdecrease and/or temperature increase, as discussed above, decreasing thestability of the foam.

One of ordinary skill in the art will appreciate, with the benefit ofthis disclosure, that the injected gas needs to have a pressure that isgreater than that of the formation into which it is being injected. Insome embodiments, the pressure of the gas may be of a range having alower limit of any of 1250, 1500, 1750, 2000, and 2500 psi to an upperlimit of any of 1500, 1750, 2000, 2250, 2500, and 3000 psi.

In one or more embodiments, the gas may be co-injected at a quality inthe range of 10 to 95%. The term “quality” is used herein to describethe volumetric flow of gas relative to the total volumetric flow in theco-injection process. In some embodiments, the quality of the gas may beof a range having a lower limit of any of 10, 15, 20, 25, 30, 40, and50% to an upper limit of any of 40, 50, 60, 70, 80, and 95%, where anylower limit can be used in combination with anymathematically-compatible upper limit. In one or more embodiments, thequality of gas may be dependent upon the composition of the wellborefluid used. In one or more embodiments, the selected quality of gas maybe dependent upon the composition of the surface active agent packagethat is used.

In one or more embodiments, the generated foam may be more viscous thanthe injected wellbore fluid and gas. The foam may, therefore, besuitable for plugging the more permeable regions of the formation.

In one or more embodiments, the generated foam may have a viscosity at50° C. that is of the range of about 15 to 200 cP. For example, thegenerated foam may have a viscosity at 50° C. that is of an amountranging from a lower limit of any of 15, 17, 20, 25, 30, 40, 50, 60, 70,80, and 100 cP to an upper limit of any of 50, 60, 70, 80, 90, 100, 120,140, 160, 180, and 200 cP, where any lower limit can be used incombination with any mathematically-compatible upper limit.

In one or more embodiments, the generated foam may have a viscosity at100° C. that is of the range of about 10 to 140 cP. For example, thegenerated foam may have a viscosity at 100° C. that is of an amountranging from a lower limit of any of 10, 12, 15, 17, 20, 25, 30, 40, 50,and 60 cP to an upper limit of any of 20, 30, 40, 50, 60, 80, 100, 120,and 140 cP, where any lower limit can be used in combination with anymathematically-compatible upper limit.

In one or more embodiments, the generated foam may have a viscosity thatis 1.1 to 10 times that of the wellbore fluid before foaming. Forexample, the foam may have a viscosity that is of an amount ranging froma lower limit of any of 1.1, 1.25, 1.5, 2, 2.5, 3, and 5 to an upperlimit of any of 1.5, 2, 3, 4, 5, 7, and 10 times greater than that ofthe wellbore fluid before foaming, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The generated foam of one or more embodiments may have a quality (asdefined above) ranging from about 50 to 99%. In some embodiments, thequality of the foam may be of a range having a lower limit of any of 50,60, 70, 80, 90, and 95% to an upper limit of any of 55, 65, 75, 85, 95,and 99%, where any lower limit can be used in combination with anymathematically-compatible upper limit. The quality of the foam of one ormore embodiments may be dependent upon both the quality of the gas andthe composition of the surface active agent package.

The solutions have a low viscosity and, therefore, good injectivity,while the resulting foams are stable enough for use downhole. Thesefoams can reduce gas mobility by increasing the apparent viscosity anddecreasing the permeability of the gas, resulting in improved sweepefficiency by diverting the flow from high permeability zones to lowerones and, ultimately, providing improved oil recovery.

The methods of one or more embodiments of the present disclosure mayfurther comprise a pre-flushing step before the injection of thewellbore fluid. The pre-flushing step may comprise flushing theformation with a flushing solution that comprises a surface active agentpackage. The flushing solution may be an aqueous solution, and thesurface active agent package may be the same surface active agentpackage as included in the wellbore fluid. The pre-flushing may limitthe adsorption of the surface active agent package on the rock surfaceof the formation during the injection process. In some embodiments, thepre-flushing may provide a stronger foam. The suitability of the use ofa pre-flushing step may depend on the type of surface active agent androck.

The hydrocarbon-containing formation of one or more embodiments may be aformation containing multiple zones of varying permeability. Forinstance, the formation may contain at least a zone having a relativelyhigher permeability and a zone having a relatively lower permeability.During conventional injection, fluids and gases preferentially sweep thehigher permeability zone, leaving the lower permeability zoneincompletely swept. In one or more embodiments, the generated nitrogenfoam may plug the higher permeability zone, allowing subsequent fluid tosweep the low permeability zone and improving sweep efficiency.

In one or more embodiments, the formation may have a temperature rangingfrom about 80 to 250° C. For example, the formation may have atemperature that is of an amount ranging from a lower limit of any of80, 90, 100, 120, 140, 160, 180, and 200° C. to an upper limit of any of100, 120, 140, 160, 180, 200, 225, and 250° C., where any lower limitcan be used in combination with any mathematically-compatible upperlimit.

The methods of one or more embodiments may be used for enhanced oilrecovery (EOR) operations. An EOR process in accordance with one or moreembodiments of the present disclosure is depicted by, and discussed withreference to, FIG. 1. Specifically, in step 100, the wellbore fluid maybe injected into a hydrocarbon-bearing formation at an injection well.In step 110, a gas may be co-injected with the wellbore fluid orinjected after the wellbore fluid. The gas may be dispersed in thewellbore fluid in step 120, generating a foam. In step 130, after foamgeneration, a fluid may be driven through the mobile zone of theformation, displacing hydrocarbons. As the foam may plug the morepermeable zones of the formation, the fluid may preferentially displacehydrocarbons from lower permeability zones. In one or more embodiments,the hydrocarbon-displacing fluid may be a gas that is either the sameas, or different from, the gas used to generate the foam. In step 140,the displaced hydrocarbons may be recovered. In one or more embodiments,the hydrocarbons may be recovered at a production well. In one or moreembodiments, the hydrocarbon-displacing fluid may be introduced into thereservoir through a wellbore or other protrusion, drill hole, oropening. In some embodiments, the fluid may be introduced at a locationdifferent from the wellbore in which the wellbore fluid is introduced.The fluid may be introduced at an elevated pressure sufficient to ensuresubstantial infiltration of the fluid into the fracture network of theformation and substantial exposure of the porous matrix of theformation. The hydrocarbons that are displaced may be recovered at thesame or a different location than the location of the introduction ofthe fluid.

In one or more embodiments, the EOR process may be repeated one or moretimes to increase the amount of hydrocarbons recovered. In someembodiments, subsequent EOR processes may involve the use of differentamounts of the surface active agent packages and/or different surfaceactive agent packages than the first. The methods of one or moreembodiments may advantageously provide improved sweep efficiency.

The methods of one or more embodiments may be used for fracturing aformation. In these embodiments, the wellbore fluid may be injected intoa hydrocarbon-bearing formation at an injection well. A gas may beco-injected with the wellbore fluid to provide a foam. The foam may bedriven through the formation at a pressure higher than the formation,opening pores and cracks present in the formation. The wellbore fluid ofone or more embodiments may contain a proppant, such as sand, that cankeep the pores and cracks of the formation open. These processes may,therefore, increase the permeability and hydrocarbon flow of theformation.

In one or more embodiments, a foam generated in a method of fracturingmay be more viscous than a foam generated in an EOR method. Therefore, amethod of fracturing may include the use of a wellbore fluid thatcontains a larger amount of thickener than a method of EOR.

EXAMPLES

The following examples are merely illustrative and should not beinterpreted as limiting the scope of the present disclosure.

Solutions containing only a surface active agent package and othersolutions containing both the surface active agent package and athickener (hydroxyethylcellulose) were prepared in deionized water. Thesurface active agent package comprised isopropanol, citrus terpenes andα-olefin sulfonate. Foam rheological properties were measured using afoam rheometer device. The gas used for foam generation was CO₂ with99.5% purity. Experiments were conducted under a CO₂ pressure of 1500psi and at two different temperatures: 50° C. and 100° C. The surfaceactive agent package was included in concentrations of 5 gpt and 10 gpt.The thickener concentration was fixed at 0.20 wt. %.

The foam rheology measurements provide an assessment of the ability ofsurfactant, and the combination of the surfactant and a thickener, toincrease the apparent viscosity as a result of foam generation. Measuredvolumes of an as-supplied surfactant stock solution were directlydissolved in deionized water to prepare 5 gpt and 10 gpt activesurfactant solutions and mixtures of the same solutions with 0.20 wt. %thickener. Rheology experimentations were conducted on a custom madeHPHT foam loop rheometer. A schematic of the apparatus is shown in FIG.2.

Foam studies were performed with sc-CO₂ under high pressure (1500 psi),and high temperature (50° C. and 100° C.). The applied shear ratesranged from 10-600 s⁻¹ and 70% quality (volume of sc-CO₂ to total volumeof injected fluids) was used. The procedure involved allowing thefoaming agent package (surfactant/mixture of surfactant and thickener indeionized water) to equilibrate in the foam loop. The sc-CO₂ was theninjected into the system and enough time was given for mixing at lowshear rate until temperature and pressure stabilized. The mixture wascirculated in the foam loop and visualized through the viewing cell toensure that foam was formed. Apparent viscosities (μ_(apparent)) werethen measured at different shear rates (γ) using the below equations.

$\begin{matrix}{\mu_{apparent} = \frac{\tau}{\gamma}} & (1) \\{\tau = \frac{D\Delta P}{4L}} & (2) \\{\gamma = \frac{8V}{D}} & (3)\end{matrix}$

where τ is the shear stress, D is the tube diameter, ΔP is thedifferential pressure across the foam loop, L is the tube length and Vis the velocity.

First, the viscosities of the solutions, surfactant and the mixture ofsurfactant and thickener, were measured at 25° C. and 50° C. to ensurethat the viscosities of solutions are very close to that of water andalso to provide a baseline for the increase of foam viscosity when thesurfactant and mixture are used to increase the sc-CO₂ viscosity. Theresults of are summarized in Table 1.

TABLE 1 Viscosity of solutions at 25° C. and 50° C., shear rate of 6.8s⁻¹ Solution Viscosity at 25° C. (cP) Viscosity at 50° C. (cP) DeionizedWater 0.890 0.546 10 gpt surfactant 0.900 0.550 5 gpt surfactant +22.100 11.200 0.20 wt % thickener

The foam rheological properties were measured at the conditions statedabove. The increase of surfactant concentration enhances the foamviscosity. FIG. 3 shows the effect of surfactant concentration on foamviscosity at 50° C. and 100° C. The addition of the thickener to thesurfactant solution was able to increase the viscosity of the foam and,accordingly, increasing the foam stability.

The foam viscosity using only 5 gpt of the surfactant and the mixture of5 gpt of surfactant and 0.20 wt. % of thickener are shown in FIG. 4. Theaddition of 0.20 wt. % of the thickener is shown to increase the foamviscosity from around 20 cP to 30 cP. Also, FIGS. 5 and 6 show the foamviscosity using 10 gpt and the surfactant and the mixture of 10 gpt ofsurfactant and 0.20 wt. % of thickener at 50° C. and 100° C.,respectively. At 50° C., the addition of the thickener produced foamwith a higher viscosity than that of the surfactant alone. The foamviscosity of the mixture was three times of the surfactant. This clearlyreflects the role of the thickener on enhancing the foam viscosity and,eventually, the stability at conditions similar to reservoir conditions.At 100° C., as shown in FIG. 6, the addition of 0.20 wt. % of thethickener to a 10 gpt surfactant solution generated foam with twice theviscosity of that using the surfactant alone. This demonstrates theeffectiveness of the wellbore fluids of one or more embodiments onenhancing the foam viscosity and stability, which are very important forthe success of the foam deployment in the field.

Although the preceding description has been described herein withreference to particular means, materials and embodiments, it is notintended to be limited to the particulars disclosed herein; rather, itextends to all functionally equivalent structures, methods and uses,such as are within the scope of the appended claims. In the claims,means-plus-function clauses are intended to cover the structuresdescribed herein as performing the recited function and not onlystructural equivalents, but also equivalent structures. Thus, although anail and a screw may not be structural equivalents in that a nailemploys a cylindrical surface to secure wooden parts together, whereas ascrew employs a helical surface, in the environment of fastening woodenparts, a nail and a screw may be equivalent structures. It is theexpress intention of the applicant not to invoke 35 U.S.C. § 112(f) forany limitations of any of the claims herein, except for those in whichthe claim expressly uses the words ‘means for’ together with anassociated function.

1. A generated foam, comprising: An aqueous wellbore fluid, comprising:a surface active agent package that comprises an α-olefin sulfonate, aterpenoid, and isopropyl alcohol, wherein the surface active agentpackage is present in an amount ranging from 1 to 20 gpt (gallons perthousand gallons) of the aqueous wellbore fluid; a thickener thatcomprises a biopolymer, wherein the thickener is present in an amountranging from 0.01 to 0.3 wt. % (weight percent) of the aqueous wellborefluid; and an aqueous base fluid; and a gas selected from the groupconsisting of carbon dioxide, methane, nitrogen, and combinationsthereof, where the gas is present in an amount such that the generatedfoam has a quality in a range of from about 50 to about 99%.
 2. Thegenerated foam of claim 1, wherein the surface active agent packagecomprises the α-olefin sulfonate in an amount in the range of 20 to 30wt. %.
 3. The generated foam of claim 1, wherein the surface activeagent package comprises the isopropyl alcohol in an amount in the rangeof 20 to 30 wt. %.
 4. The generated foam of claim 1, wherein the surfaceactive agent package comprises the terpenoid in an amount in the rangeof 10 to 20 wt. %.
 5. The generated foam of claim 1, wherein thethickener is hydroxyethylcellulose.
 6. The generated foam of claim 1,wherein the terpenoid is citrus terpenes.
 7. The generated foam of claim1, wherein the wellbore fluid has a viscosity at 25° C. of 30 cP(centipoise) or less.
 8. The generated foam of claim 1, wherein thewellbore fluid has a viscosity at 50° C. of 20 cP or less.
 9. A methodfor recovering hydrocarbons from a hydrocarbon-containing formation, themethod comprising: injecting into the hydrocarbon-containing formation awellbore fluid that comprises a surface active agent package, athickener, and an aqueous base fluid, wherein the surface active agentpackage comprises an α-olefin sulfonate, a terpenoid, and isopropylalcohol, and wherein the wellbore fluid comprises the surface activeagent package in an amount in the range of 1 to 20 gpt and the thickenerin an amount in the range of 0.01 to 0.3 wt. %; injecting into thehydrocarbon-containing formation a gas that mixes with the wellborefluid, generating a foam in the formation; introducing a fluid into thehydrocarbon-containing formation, thereby displacing hydrocarbons fromthe hydrocarbon-containing formation; and recovering the hydrocarbons.10. The method of claim 9, wherein the wellbore fluid and the gas areco-injected.
 11. The method of claim 9, wherein the gas is injectedafter the wellbore fluid.
 12. The method of claim 9, wherein thehydrocarbon-containing formation comprises a zone of high permeabilityand a zone of low permeability.
 13. The method of claim 9, wherein thegenerated foam may have a viscosity that is 1.1 to 10 times that of thewellbore fluid before foaming.
 14. The method of claim 9, wherein thesurface active agent package comprises the α-olefin sulfonate in anamount in the range of 20 to 30 wt. %.
 15. The method of claim 9,wherein the surface active agent package comprises the isopropyl alcoholin an amount in the range of 20 to 30 wt. %.
 16. The method of claim 9,wherein the surface active agent package comprises the terpenoid in anamount in the range of 10 to 20 wt. %.
 17. The method of claim 9,wherein the thickener is hydroxyethylcellulose.
 18. The method of claim9, wherein the terpenoid is citrus terpenes.
 19. The method of claim 9,wherein the generated foam has a viscosity at 50° C. of 15 to 200 cP.20. The method of claim 9, wherein the generated foam has a viscosity at100° C. of 10 to 140 cP.
 21. A method of preparing an aqueous wellborefluid, comprising: mixing a surface active agent package, a thickener,and an aqueous base fluid, wherein the surface active package comprisesan α-olefin sulfonate, a terpenoid, and isopropyl alcohol and thethickener comprises a biopolymer, wherein the wellbore fluid containsthe surface active agent package in an amount ranging from 1 to 20 gpt,and wherein the wellbore fluid contains the thickener in an amountranging from 0.01 to 0.3 wt. %.
 22. The method of claim 21, wherein thesurface active agent package comprises the α-olefin sulfonate in anamount in the range of 20 to 30 wt. %.
 23. The method of claim 21,wherein the surface active agent package comprises the isopropyl alcoholin an amount in the range of 20 to 30 wt. %.
 24. The method of claim 21,wherein the surface active agent package comprises the terpenoid in anamount in the range of 10 to 20 wt. %.
 25. The method of claim 21,wherein the thickener is hydroxyethylcellulose.
 26. The method of claim21, wherein the terpenoid is citrus terpenes.
 27. The method of claim21, wherein the wellbore fluid has a viscosity at 25° C. of 30 cP orless.
 28. The method of claim 21, wherein the wellbore fluid has aviscosity at 50° C. of 20 cP or less.
 29. A method for enhancing therecovery of hydrocarbons from a hydrocarbon-containing formation, themethod comprising: injecting into the hydrocarbon-containing formation awellbore fluid that comprises a surface active agent package, athickener, and an aqueous base fluid, wherein the surface active agentpackage comprises an α-olefin sulfonate, a terpenoid, and isopropylalcohol, and wherein the wellbore fluid comprises the surface activeagent package in an amount in the range of 1 to 20 gpt and the thickenerin an amount in the range of 0.01 to 0.3 wt. %; and injecting into thehydrocarbon-containing formation a gas that mixes with the wellborefluid, generating a foam in the formation.
 30. The method of claim 29,wherein the wellbore fluid and the gas are co-injected.
 31. The methodof claim 29, wherein the gas is injected after the wellbore fluid. 32.The method of claim 29, wherein the hydrocarbon-containing formationcomprises a zone of high permeability and a zone of low permeability.33. The method of claim 29, wherein the generated foam may have aviscosity that is 1.1 to 10 times that of the wellbore fluid beforefoaming.
 34. The method of claim 29, wherein the surface active agentpackage comprises the α-olefin sulfonate in an amount in the range of 20to 30 wt. %.
 35. The method of claim 29, wherein the surface activeagent package comprises the isopropyl alcohol in an amount in the rangeof 20 to 30 wt. %.
 36. The method of claim 29, wherein the surfaceactive agent package comprises the terpenoid in an amount in the rangeof 10 to 20 wt. %.
 37. The method of claim 29, wherein the thickener ishydroxyethylcellulose.
 38. The method of claim 29, wherein the terpenoidis citrus terpenes.
 39. The method of claim 29, wherein the generatedfoam has a viscosity at 50° C. of 15 to 200 cP.
 40. The method of claim29, wherein the generated foam has a viscosity at 100° C. of 10 to 140cP.